Real-Time Determination of OBM Filtrate Contamination During Openhole Wireline Sampling

Mullins, Oliver C.; Schroer, Jon

doi:10.2118/0201-0024-jpt

Cited by 12 publications

(18 citation statements)

References 2 publications

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“…The first generation of downhole fluid analyzer tools was primarily for real time monitoring of OBM contamination in dowhole fluid samples (Mullins et al, 2000;Fadnes et al, 2001) as well as to distinguish hydrocarbon and water (Smits et al, 2000). The DFA technique utilizes optical spectroscopy spectrum of crude oils, gases, OBM filtrates and water in the visible and near infrared (NIR) wavelength regions as shown in Figure 1-a.…”

Section: Downhole Fluid Analysismentioning

confidence: 99%

Reservoir Architecture Characterization From Integration of Fluid Property Distributions With Other Logs

Dong

Chun²,

Majkut

et al. 2009

SPE Offshore Europe Oil and Gas Conference and Exhibition

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Characterizing reservoir architecture and fluid property distributions at the early exploration and appraisal stage are critical for reservoir assessment, planning and management. Particularly for thinly laminated reservoirs, identification of hydrocarbon-bearing zones and determination of the flow unit sizes have profound impact on long term production predictions. In this paper, a case study is presented that integration of reservoir fluid property distribution with other logs leads to accurate reservoir understanding. In this method, downhole fluid analysis (DFA) is used to identify key production parameters of reservoir fluids in real time and at downhole conditions. DFA results are combined with other logs to develop a view of reservoir architecture especially pinpointing thin pay zones with low resistivity, which could be treated as wet by open-hole logs. Indeed, 19 DFA stations were performed in this particular well and represents a typical number of DFA stations per well in this field (another well in this field had significantly more DFA stations that established a world record). The results of the improved interpretation are confirmed by subsequent well test data. The case study indicates that the methodology of integrating DFA with other logs provides a powerful and cost effective approach for reservoir understanding and assessment at the exploration stage, which is invaluable for optimal reservoir management and development planning.

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Section: Downhole Fluid Analysismentioning

confidence: 99%

Reservoir Architecture Characterization From Integration of Fluid Property Distributions With Other Logs

Dong

Chun²,

Majkut

et al. 2009

SPE Offshore Europe Oil and Gas Conference and Exhibition

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“…After synchronized pumping started in both sample and guard flow lines at 2,200 seconds, the density from the DFA tool decreased quickly from 1.1 g/cm 3 and then stabilized at 0.97 g/cm 3 . The same principle as used with optical spectroscopy for OBM contamination monitoring 13,14 can be applied to the density change in Fig. 21.…”

Section: Casementioning

confidence: 99%

“…[2][3][4][5][6][7][8][9][10][11][12] Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-base mud (OBM) or water-base mud (WBM), fluid sample contamination from the drilling fluid is estimated. 13,14 With the DFA technique, reservoir fluid samples are analyzed before they are taken, and the quality of fluid samples is substantially improved. The sampling process is optimized in terms of where and when to sample, and how many samples to take.…”

Section: Introductionmentioning

confidence: 99%

New Downhole Fluid Analyzer Tool for Improved Reservoir Characterization

Dong

O'Keefe

Elshahawi

et al. 2007

SPE Offshore Europe Oil and Gas Conference and Exhibition

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fax 01-972-952-9435. AbstractDownhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proven and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO 2 ). For single-phase assurance it is possible to detect gas liberation (bubble point) or liquid dropout (dew point) while pumping reservoir fluid to the wellbore, before filling a sample bottle.In this paper, a new DFA tool is introduced which greatly increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: methane (C1), ethane (C2), propane to pentane (C3-5), C6+, and CO 2 . These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with much greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single well to multi-well. Field-based fluid characterization is now possible.In addition a new measurement is introduced -in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers, fluid resistivity, pressure, temperature, and fluorescence measurements that all play a vital role in determining the exact nature of the reservoir fluid.Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to emulate reservoir conditions. In addition several field examples are presented to illustrate applicability in different environments.

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“…8, , , , 9 10 11 12 Due to the complexity of miscible flow 13 , limited work has been advanced to simulate invasion by OBMs. Chin et al 14 instroduced a strategy to quantify clean fluid sampling times in the presence of miscible flow.…”

Section: Introductionmentioning

confidence: 99%

Robust and Efficient Simulation of Formation-Tester Measurements with a Rigorous Compositional Simulation Code

Malik

Torres‐Verdín

Sepehrnoori

2006

SPE Annual Technical Conference and Exhibition

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes the development, testing, and successful application of a new compositional code for the numerical simulation of oil-base mud invasion and formation tester measurements that involve arbitrary miscibility between oilbase mud and native oil. The simulator assumes axialsymmetric variations of petrophysical properties as well as axial-symmetric flow-rate sources and boundary conditions. However, there are no restricting assumptions to the degree of miscibility between the fluids involved in the simulations. We solve the time-space evolution of component concentration with a time-marching implicit pressure explicit concentration (IMPEC) scheme. This method of solution considers the complete equations of state and implements rigorous and efficient flash calculations to describe the thermo-dynamical evolution of the various compositional phases due to spacetime variations of pressure and concentration.Simulations described in this paper consider the process of oil-base mud-filtrate invasion into reservoirs containing mixtures of connate water and oil. Subsequently, we simulate formation tester measurements by enforcing fluid withdrawal through the dual-packer section of the tester. Measurements consist of fluid pressure, fractional flow rates, fluid density, and fluid viscosity. Examples of application include homogenous and multi-layer formations as well as a capillarytransition zone. Comparison of simulation results against those obtained with a commercial code confirms the efficiency, accuracy, and reliability of our simulator.Sensitivity analysis indicate that time evolution of fractional flow rates, fluid density, and fluid viscosity measured with the formation tester remain influenced by the petrophysical properties of the formation as well as by relative permeability and capillary pressure. The simulations described in this paper accurately predict the measurement times necessary for the acquisition of clean samples of native formation oil in the presence of invasion and heterogeneous spatial distributions of petrophysical and rock-fluid properties.

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Real-Time Determination of OBM Filtrate Contamination During Openhole Wireline Sampling

Abstract: E&P Exchange - SPE 70479

Cited by 12 publications

References 2 publications

Reservoir Architecture Characterization From Integration of Fluid Property Distributions With Other Logs

Reservoir Architecture Characterization From Integration of Fluid Property Distributions With Other Logs

New Downhole Fluid Analyzer Tool for Improved Reservoir Characterization

Robust and Efficient Simulation of Formation-Tester Measurements with a Rigorous Compositional Simulation Code

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